The invention relates to a process for pretreating a very acid natural gas containing a substantial amount of hydrogen sulfide (H2S), possibly combined with carbon dioxide (CO2).
When a gas producer is confronted with the task of treating a very acid natural gas containing, for example, more than 20% by mole of hydrogen sulfide, more especially knowing that the gas production capacity is above 2 million m3 per day and that sulfur production is economically not justified, this gas producer is faced with a dilemma: the major part of the hydrogen sulfide has to be eliminated while safety regulations and environmental requirements have to be met. Furthermore, economic requirements impose the lowest possible enenrgy consumption as regards hydrogen sulfide separation and elimination.
Sometimes, elimination of hydrogen sulfide and carbon dioxide from natural gas can be solved by reinjecting the mixture recovered into a reservoir nearing depletion, which saves downstream installation of sulfur recovery plants that are costly and whose energy consumption is high.
In order to be able to sell a gas containing less than 3 ppm by volume of hydrogen sulfide, separation techniques that have to be selective towards this poison must be used, since simultaneous elimination of carbon dioxide and of H2S does not involve the same purity requirements. In fact, 2 to 4% by volume of CO2 are allowed in the gas intended for sale. This objective can be reached by means of a process involving two stages, a stage of partial reduction of the acid content by means of a membrane separation process, followed by a stage of washing of the thus partly purified gas, by means of a solvent or of a selective amine. It is in fact well-known that selective membranes allow more readily diffusion of H2S and CO2 than of the hydrocarbons (notably methane) contained in the natural gas. This a priori simple process however involves serious drawbacks, notably when the H2S-rich acid gas is to be reinjected into the reservoir at high pressure. What is referred to as hydrocarbons in the present document is a mixture essentially containing methane and low proportions of ethane, propane and butane.
The main drawback of pretreating by permeation on a membrane lies in the fact that the permeate rich in H2S and CO2 has to be recovered downstream from the membrane under very low pressure for the process to be efficient. It follows therefrom that, if the gas is neither flared nor sent to a sulfur recovery plant, it is imperative to recompress it to the pressure of the reservoir, which leads to a high compression cost and to a considerable energy consumption.
A second drawback of the membrane permeation process is due to the fact that this membrane is not perfectly selective towards acid gases since it allows considerable diffusion of methane in the permeate. The marketable methane loss can represent 10 to 15% of the feed introduced.
One of the objects of the invention is to pretreat a natural gas very rich in H2S and in CO2 so that it can be used and marketed without harming the environment.
The present invention also allows to dehydrate said gas and to eliminate most of its acid constituents, in liquid form, in a reservoir nearing depletion.
The work carried out by the applicant has allowed to propose, in patent FR-B-2,715,692, a process allowing to eliminate a substantial amount of the acid gases present in the initial natural gas, i.e. at the well outlet, a process whose simplicity allows it to be readily implemented with a minimum investment.
According to said process, the initial natural gas is contacted in a cyclone type enclosure with a liquid condensate itself resulting from cooling of the gaseous fraction obtained during said contacting stage. This solution allows to eventually recover, at a lower cost, a gas enriched in methane and depleted in hydrogen sulfide, and a liquid phase at the bottom of the enclosure comprising the major part of the hydrogen sulfide, water, and depleted in hydrocarbon, said liquid phase being then reinjected into a well nearing depletion. The process described in patent FR-B-2,715,692 however involves several drawbacks:
1) The presence of water in the hydrogen sulfide-rich liquid solutions cooled to a low temperature (down to xe2x88x9230xc2x0 C.) may lead, in the whole circuit, to the formation of hydrates that can eventually clog the lines, or even damage the elements that make up the device used. The process according to the prior art therefore recommended to use an antihydrate agent, preferably methanol, to prevent hydrate formation during cooling of the gaseous effluent coming from the cyclone.
Calculations carried out by the applicant show that, under the conditions described in patent FR-B-2,715,692, it is necessary to use a large amount of methanol to prevent hydrate formation. Thus, a fictitious feed of 100 kmol/h (kilomoles per hour) containing 30% by mole of H2S and 10% by mole of CO2 comprises 0.35% by mole of water at 50xc2x0 C. and at a pressure of 8 MPa (MegaPascals) in the initial gas feed, 1.12% by mole of water in the liquid present in the bottom of the cyclone and 700 ppm (parts per million) by mole in the liquid condensate (xe2x88x9230xc2x0 C. and 8 MPa). Now, in order to inhibit hydrate formation at xe2x88x9230xc2x0 C., a MeOH/H2O molar ratio of 15 is required under such conditions. This requires 1% by mole of methanol in the liquid phase, i.e. an amount of 3200 kg/h (kilogram per hour) for a flow of gas of 25000 kmol/h. Finally, this methanol is difficult to recover because it is carried along with the flow of liquid H2S and it cannot be satisfactorily separated. In fact, it is thermodynamically difficult to separate the water-methanol mixture from the H2S-rich condensate in the cold drum because, under the conditions that prevail in the drum, there is only one liquid phase where all the products are soluble. Similarly, during contacting, on account of the vapour pressure of the products, a large amount of the methanol is carried along with the products at the bottom of the column and cannot be discharged at the top with the methane.
2) The calculations carried out show that, under the conditions described in patent FR-B-2,715,692, an appreciable amount of hydrocarbons is carried along with the liquid phase recovered at the bottom of the cyclone. By way of example, the hydrocarbon losses would amount to about 8% by mole in the case studied above.
One of the objects of the invention is to overcome the aforementioned drawbacks.
The applicant has discovered, which is one of the objects of the present invention, that it is possible, under suitable thermodynamic conditions, to concentrate the initial natural gas in methane while removing most of the acid gases and substantially all of the water it contains. In the latter expression, it is understood that the amount of water present in the final gas is less than 50 ppm by mole, preferably less than 10 ppm by mole and more preferably less than 5 ppm by mole.
The invention also relates to a process allowing to prevent hydrate formation in all the stages of the device allowing said methane concentration.
According to the present invention, after treating the natural gas from the production well according to the present process, a final gas containing most of the hydrocarbons contained in said gas is recovered. Most of the hydrocarbons means at least 90% of hydrocarbons, preferably at least 95% of hydrocarbons and more preferably at least 97% of hydrocarbons.
Finally, the present invention advantageously allows to save using an antihydrate agent such as methanol whose transport, use and/or recovery can be costly and/or complex.
More generally, the invention relates to a process for pretreating a natural gas under pressure containing hydrocarbons, at least one of the acid compounds hydrogen sulfide and carbon dioxide, and water, wherein:
a) the natural gas is cooled to produce a liquid phase and a gas phase,
b) the gas phase obtained in stage a) is contacted in a distillation column with a liquid phase obtained in stage c) to produce a gas phase and a liquid phase,
c) the gas phase obtained in stage b) is cooled to produce a liquid phase and a gas phase.
In stage c) of the process according to the invention, the gas phase obtained in stage b) can be cooled by means of a heat exchanger and/or of an expander.
The process according to the invention can comprise the following stage:
d) the gas phase obtained in stage c) is cooled by means of an expander so as to produce a gas phase and a liquid phase that is recycled to stage b).
The process according to the invention can comprise the following stage:
e) at least one of the gas phases obtained in stage c) and in stage d) is compressed by using the energy recovered from the expander.
In stage c) of the process according to the invention, the gas phase obtained in stage b) can be cooled by means of a venturi neck, said liquid phase being discharged in the vicinity of the venturi neck and said gas phase being recovered at the outlet of the divergent tube of the venturi neck. The liquid phase collected in the vicinity of the venturi neck can be cooled to produce the liquid recycled to stage b) and a gas phase.
The gas phases obtained in stage c) and in stage d) can be used to cool the gas phase obtained in stage b) and/or to cool the natural gas in stage a).
The process according to the invention can comprise the following stage:
f) at least part of the liquid phase obtained in stage b) is vaporized and said vaporized at least part of the liquid phase is fed into the distillation column to create an ascending vapour flow in said column.
According to the present invention, part of the heat of the liquid phase obtained in stage b) can be used to heat the gas phase obtained in stage a).
In stage a) of the process according to the invention, the liquid phase and the gas phase can be separated in a drum, and at least part of the liquid phase obtained in stage b) can be fed into said drum.
The operating conditions of the process according to the invention can be as follows:
Distillation column of stage b)
Txc2x0 C.=xe2x88x9220xc2x0 C. to 100xc2x0 C., preferably xe2x88x9215xc2x0 C. to 70xc2x0 C.
P greater than 1 MPa abs., preferably 4 to 10 MPa abs.
Pressure and cooling temperature in stage c)
Txc2x0 C.=xe2x88x92100xc2x0 C. to +30xc2x0 C., preferably xe2x88x9240xc2x0 C. to 0xc2x0 C.
P greater than 1 MPa, preferably 4 to 10 MPa
Temperature to which said natural gas is cooled in stage a)
0 to 50xc2x0 C., preferably 20 to 40xc2x0 C.
According to the present invention, the partial pressure of the hydrogen sulfide in the natural gas can be at least 0.5 MPa, preferably at least 1.5 MPa. The distillation column can comprise at least 3 theoretical stages, preferably 4 to 6. In stage a), the natural gas can be at a pressure ranging between 6.5 MPa and 12 MPa, and at a temperature above 15xc2x0 C.
The liquid phases obtained in stages a) and b) can be introduced into a well.
Thus, one of the main features of the process according to the present invention lies in the control of the thermodynamic conditions (pressure and temperature for example) according to the nature of the gas treated (notably its water content), said control allowing progressive exhaustion of the water contained in said gas while preventing hydrate formation. In general, according to the present process, a distillation column allowing progressive exhaustion of the water content from the bottom to the top of the column will be used, so as to recover at the top of said column a gas substantially freed from the water it contained, i.e. comprising an amount of water that is lower than the hydrate formation limit at the lowest temperature reached during cooling and expansion condensation stage c). In particular, according to the invention, the water-saturated gas obtained in stage a) will be introduced at a sufficiently low level of the column, i.e. at a sufficiently high temperature, to prevent hydrate formation. Said column must therefore contain a sufficient number of theoretical stages to allow water exhaustion and to obtain a temperature gradient between the cold top and the bottom of the column. Furthermore, addition of a reboiler advantageously allows to maintain a sufficiently high temperature in the column and thereafter to prevent hydrate formation, as well as to minimize and/or control hydrocarbon losses.